Reservoir systems, such as petroleum reservoirs, typically contain fluids such as water and a mixture of hydrocarbons such as oil and gas. To produce the hydrocarbons from the reservoir, different mechanisms can be utilized such as primary, secondary or tertiary recovery processes.
In a primary recovery process, hydrocarbons are displaced from a reservoir due to the high natural differential pressure between the reservoir and the bottomhole pressure within a wellbore. The reservoir's energy and natural forces drive the hydrocarbons contained in the reservoir into the production well and up to the surface. Artificial lift systems, such as sucker rod pumps, electrical submersible pumps or gas-lift systems, are often implemented in the primary production stage to reduce the bottomhole pressure within the well. Such systems increase the differential pressure between the reservoir and the wellbore intake; thus, increasing hydrocarbon production. However, even with use of such artificial lift systems only a small fraction of the original-oil-in-place (OOIP) is typically recovered using primary recovery processes as the reservoir pressure, and the differential pressure between the reservoir and the wellbore intake, declines overtime due to production. For example, typically only about 10-20% of the OOIP can be produced before primary recovery reaches its limit—either when the reservoir pressure is too low that the production rates are not economical, or when the proportions of gas or water in the production stream are too high.
In order to increase the production life of the reservoir, secondary or tertiary recovery processes can be used. Typically in these processes, fluids such as water, gas, surfactant, or combination thereof, are injected into the reservoir to maintain reservoir pressure and drive the hydrocarbons to producing wells. For example, typically an additional 10-50% of OOIP can be produced in addition to that produced during primary recovery. The most commonly used secondary recovery process is waterflooding, which is often referred to as an improved oil recovery (IOR) process, and involves the injection of water into the reservoir to displace or physically sweep the residual oil to adjacent production wells.
Waterflooding operations typically require a sufficient supply of water for injection, water purification systems to filter and chemically treat the source water, a pumping or injection system, and access to the reservoir formation via a wellbore. While waterflooding processes may be more economical than other oil recovery processes, waterflooding operations present logistical and economic limitations that can preclude the use of waterflooding, especially when operating in offshore environments.
In offshore or marine waterflood operations, the production and injection wells are subsea, or below a body of water, and access to the wells is primarily via a platform or production vessel. Produced water can be processed and used as a supply source of injection water; alternatively, seawater can be recovered, treated, and injected into the injection wells. Such fluid processing/treatment facilities are often located on centralized injection platforms connected to various injection wells via submarine pipelines, as the injection wells are typically positioned remotely along the perimeter of the reservoir.
The capital and operational costs, as well as, logistical constraints of a waterflood therefore, often dictate whether waterflooding is a feasible candidate for recovery in a reservoir. Historically waterflooding in marginal oil reservoirs, where the OOIP typically ranges between 0.25-2 million stock tank barrels (MMSTB), has not been feasible, even when incremental waterflood reserves could be up to double those of primary reserves. For example, the predicted incremental oil obtained from waterflooding marginal offshore reservoirs typically would not offset the cost of injection pumps and laying pipelines supplying injection water to the remote platforms. Waterflood recovery is also dependent on the timing of water injection and delays in getting water in the ground may result in loss of recovery. Furthermore, seawater injection systems installed on remote platforms are structurally not viable as they are challenged by weight constraints, space constraints, and limited mobility.